0

5

10

15

20

25

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35

X<10 10<X<20 20<X<25 25<X<30 X>30

AGE RANGE, X ( Y EARS)

BAKAU BARAM BARONIA BETTY

BOKOR FAIRLEY BARAM TUKAU WEST LUTONG

SIWA BAYAN D18 TEMANA

D35 E11

Copyright 2006, Society of Petroleum Engineers This paper was prepared for presentation at the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, 11–13 September 2006. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Petronas Carigali Sdn Bhd (PCSB) is currently operating in excess of 150 Platforms. Of these over 60% have been in operation for more than 20yrs, 20% of platforms have already exceeded 30yrs with several others in the very near future reaching their initial design life (20-25yrs).

Increasing demand to extend the life of these platforms due to further oil/gas discoveries can result in the platform being subjected to higher loading due to required modifications/ upgrading and work-over demands for which the platform may not have been originally designed for. Furthermore, the need to undertake more frequent detail inspections due to long-term fatigue phenomena also requires managing.

In addition to the above PCSB platforms may also be faced with other challenges/events such as more onerous code requirements, increase in environmental metocean loading, presence of shallow gas and seismic/earthquake loading for which again the structure may have not been initially designed for. As such PCSB must be able to manage these events and justify the on going integrity and fitness for purpose of its platforms.

This paper describes the challenges and solutions faced in managing the ongoing long-term structural integrity of its ageing platforms. Several key assessment procedures, tools and technology initiative improvement programs will be covered in detailed to highlight their importance in managing the long-term integrity of the structures. In addition the implementation of such assessment procedures, tools and technology improvements are being used to assist in the ongoing development of a Carigali Structural Integrity Management System (CSIMS). The process adopted (as described in this paper) is to be inline with the recent development of a standalone Recommended Practice (RP) API RP 2SIM, for the Structural Integrity Management of existing

structures (currently applicable to Gulf of Mexico), to extend its applicability to Non-US Waters. As such PCSB has recently joined a JIP (Joint Industry Project) initiative involving a number of Non-US Oil/Gas Operators to extend the applicability of the RP 2SIM to Non-US Waters. Introduction

Petronas Carigali SND BHD (PCSB) currently operates in the domestic waters of Malaysia namely Penisular Malaysia Operations (PMO), Sarawak Operations (SKO) and Sabah Operations (SBO) over 150 Platforms respectively. The number of facilities for each of the regions by platform operation years is shown in Table 1. It can be seen from Table 1 that several of these platforms have been in operation for more than their original intended design life of 20/25 yrs and 20% have been operating beyond 30 yrs. In particular the largest number of facilities and oldest platforms are located in SKO region as shown in Fig. 1 with over 50% greater than 25yrs and 30% exceeding 30yrs.

Age Distribution, x (Years) x<10 10<x<20 20<x<25 25<x<30 x>30

PMO 13 5 13 4 SBO 1 3 7 10 6 SKO 1 33 17 19 33

Table 1 - PCSB Platform Profile – Age Distribution

Fig. 1 – SKO Facilities Age Distribution

SPE 101000

Managing Structural Integrity for Aging PlatformN.W. Nichols, Petronas Carigali Sdn Bhd; T.K. Goh, Petronas Research & Scientific Services Sdn Bhd; and H. Bahar, Petronas Carigali Sdn Bhd

2 SPE 101000

A number of platforms have been extended beyond their original intended life as a result of additional oil/gas discoveries and therefore there is a need to address the ongoing structural integrity of these platforms. A number of factors, which may trigger reassessment of platforms, are for example as follows: • Changes in design codes • Increase in metocean loading • Tie in, work over, additional topside facilities • Damaged or loss of members • Different application/usuage of the platform (i.e platform

now required for living quarters) In addition to the above, new challenges for which

platforms were not originally designed for may become apparent such as: • Shallow Gas: - Field developments may shown signs of

the presence of shallow gas layers below the jacket pile foundations and in some cases these layers could be confined within the depths that the jacket piles have been driven to. The presence of shallow gas can have an impact on the pile bearing capacity (i.e. reduction in skin friction) and subsidence can possibly occur.

• Seismic Loading: - as a result of the Indonesian tsunami/earthquake event in December 2004 and earthquakes occurring in the vicinity of offshore Sarawak and Sabah.

Due to the nature of one or more of the above triggers structural reassessments have to be conducted. The current practice of PCSB is to follow the Recommended Practice (RP), working stress design approach (WSD) of API RP2A [1] as shown in Fig. 2.

Fig. 2 - Flow Diagram of Structural Integrity Reassessment (API Code Check)

The API RP2A WSD method of design of offshore structures is based on traditional engineering practice, which applies a combination of loads to the structure to determine the internal forces in each brace member. For each member and joint in the structure an allowable strength is provided in the design, and the structure is considered to meet the selected standard if all the individual components satisfy the requirements. Within this design procedure is the premise that failure of one

member or joint to satisfy the requirements, constitutes non-compliance with the relevant RP. Therefore, the primary objective when applying the code is to ensure that component strength/foundation capacity and fatigue of the various components do not violate the minimum code requirements. Should the reassessment indicate that the above requirements are not meet there is a need to undertake more detail assessments, which normally involve more complex analysis as, shown in Fig. 3. Fig. 3 – Flow Diagram for Detail Structural Integrity Assessment

However, the assessments shown in Fig. 3 requires amongst other things detail knowledge and understanding of the non-linear behaviour of the structure and the application of risk based inspection (RBI) and structural reliability based (SRA) assessments. An alternative approach as shown in Fig. 4 before embarking on such detail assessments is to consider the conservatisms inherent within the current RP as well as the application of recent engineering improvements not captured within current code.

Fig. 4 – Flow Diagram Showing Areas of Structural Integrity Improvements for Code Assessment

When undertaking re-assessments, PCSB has identified for a number of its platforms two significant areas of non compliance to RP involving the prediction of low factor of safety (FOS) for pile foundation capacity and low fatigue lives significantly less than the required design life. As such these non-compliances to the design approach, where the structure is considered as numerous components and checked for compliance with RP prescribed allowable stresses and FOS is

Issue 1 Issue 2

Compliance with the API Code

Common Problem

Ageing Jackets in Malaysia

Component Strength/ Foundation Requirement

Component Fatigue Life Requirement

Are there any structural jacket/foundation components violating the minimum requirements?

Are there any structural jacket primary joints violating the minimum requirement?

Ageing Jackets in Malaysia

RSR /Member Importance Analysis/SRA

Optimum Inspection /RBI

Structural Integrity of Existing Ageing Jackets

Not meeting Code requirements

Assessing Maintaining

Not meeting code requirements

Improve Current Assessments (Before Detail Assssesments)

Ageing Jackets in Malaysia

Foundation New Pile Design Ageing Effects

Historical Data/Observations S-N Curves

Local Joint Flexibility

Component Strength/ Foundation Requirement

Component Fatigue Life Requirement

Issue 1 Issue 2

SPE 101000 3

not always a rational or cost efficient means of demonstrating the fitness-for-purpose of a structure. In some cases it may prevent a field development from proceeding or involve very costly and often hazardous underwater inspection, strengthening or modifications. An assessment approach involving improvements to current code assessment, applying recent engineering improvements which reduce the inherent conservatisms in the RP approach related to both foundation and fatigue are shown in Fig. 4, respectively. These two areas of improvement will be addressed in further detail below. Fatigue Assessments

Offshore steel jacket structures consist primarily of tubular joints, which are formed by the intersection of brace and chord members. The complex geometry at joint intersections results in stress concentrations of varying intensity. Wave loading causes fluctuations in stresses around the intersections, potentially leading to fatigue induced crack growth and ultimately failure. Fatigue failure is defined as the number of stress cycles, a function of time, taken to reach a pre-defined failure criterion. Fatigue failure analysis is not a rigorous science and the idealizations and approximations inherent in it prevent the calculation of absolute fatigue lives. Nevertheless, the prediction of fatigue lives is essential for the life-cycle management of an offshore installation.

Historical Observations of In-Service Fatigue Cracking

Despite the efforts described above it is recognized within the offshore community that fatigue life predictions for steel jacket structures tend to under-predict the lives of the joints. With the growth of platform operating experience over time, it has become clear that the number of occurrences of fatigue cracks discovered in existing structures is not as high as would be expected. To demonstrate this Table 2 shows a summary of results obtained from a study carried out to compare observed and predicted fatigue cracks in North Sea Jackets O.T Vardal et al [2] for over 4000 NDT (Non-destructive Testing) inspection results from period 1972-1995, including 600 Platform years.

Yea

r of

inst

alla

tion

No

of

stru

ctur

es

No

of

obse

rvat

ion

prop

agat

ing

crac

ks

No

of

obse

rvat

ion

crac

ks

No

of

insp

ectio

n ob

serv

atio

ns

No

of e

ffect

ive

obse

rvat

ions

Before 1975 8 167 309 1943 1677 1975-1978 14 48 178 1732 1582 After 1978 8 6 24 299 278 Sum 30 221 511 3974 3537

Table 2 – Observations as a Function of Installation Year (No. Of Cracks Inspections)

From this study, fatigue crack predictions and observations were compared by the over-prediction ratio defined as the ratio between the sum of estimated probability for fatigue crack detection and the sum of fatigue cracks, as shown in Table 3. The number of propagating cracks, which were, detected being dependent on the fatigue crack confidence criterion (Fat x%). Table 3 gives the overprediction ratios for all data collected and different sub sets of data and shows

oveprediction of propagating fatigue cracks to be conservative and typically 3 to 10 times too high. The reason for the lack of correlation is in the degree of conservatism in the conventional fatigue design procedure. Two significant areas where this is observed is in the application of the fatigue S-N curve used in predicting the fatigue life of tubular joints and the modeling of the actual joint when using structural analysis such packages such as SACS [3] used widely by offshore community.

CRITERIA (FAT x%)

Yea

r of i

nsta

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n

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of p

redi

cted

pr

opag

ate

crac

ks

Ove

r pre

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ratio

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%)

Ove

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ratio

(FA

T 70

%)

Ove

r pre

dict

ion

ratio

(FA

T 90

%)

Before 1975 449 2.7 3.5 6.9

1975-1978 284 5.9 9.8 18.9

After 1978 56 9.3 27.8 ∞

Sum 789 3.6 5.0 9.9 Table 3 – Overprediction Ratio (No of predicted propagating cracks/the no of detected propagating cracks for different fatigue crack confidences) S-N Curves used in Fatigue Assessments

When adopting API RP 2A[1] one of the main parameters in estimating fatigue lives for tubular joints is the use of Fatigue S-N curves namely the X curve or X’ curve. The X’ curve (lower bound) is applicable for welded joints which conform to the basic AWS weld profile [4], whilst the X curve (upper bound) is applicable for welds with profile control. The reality is that for many of the existing platforms the condition of the weld profile is not known (due to lack of fabrication data being available) and therefore the lower bound curve is adopted. However the international standardization organization (ISO) has been developing draft guidelines 19902 for fixed steel platforms [5] which contain recommendations for use of new S-N curves for fatigue assessments of tubular joints. This S-N curve is known as the ISO TJ curve, which is applicable for standard weld profile conditions and has been developed for both in-air (TJ air) and seawater conditions with cathodic protection (TJCP). These curves are shown in Fig. 5, together with those from API (X and X’), air and seawater (SW) curves and experimental tubular joint fatigue endurance data (N3) for CP (cathodic protection) normally adopted.

10

100

1000

1.E+03 1.E+04 1.E+05 1.E+06 1.E+07 1.E+08

Fatigue Endurance (N3)

Thic

knes

s C

orre

cted

Hot

Spo

t Str

ess

Ran

ge (M

Pa)

X' SW

X Air

X' Air

Data Points N3

ISO TJ curve air

ISO TJ curve swcp

Fig. 5 – Comparison of ISO/API S-N Curves in Air/SeawaterCP

4 SPE 101000

It can be seen from Fig. 5 that the ISO S-N curve represents a better fit to the experimental data than those adopted by API, which are shown to be conservative. The conservatism between both S-N curves is illustrated in Fig. 6 for a range of hot spot stress ranges. It can be seen from Fig. 6 that the difference in fatigue life predictions using ISO as opposed to API, varies significantly depending on the actual hot spot stress range that the joint is experience. Factors greater than 5 are noted for low stress ranges, which would typically be experienced during the life of the structure.

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Hot spot stress range, N/mm2

(ISO

)/(A

PI)

Fig. 6 – Comparison of Fatigue Life Ratio ISO versus API

Flexible Joint Fatigue Analysis

Recent studies such as Lalani [6] indicate that the structural analysis is the principal cause of this conservatism. It has been usual practice to assume that tubular joints are rigid when performing fatigue analyses, usually due to a lack of knowledge on how to better represent the true behaviour that is observed in large-scale component and frame tests [6]. The technology now exists to address the question of local joint flexibility (LJF) and reflect it in the fatigue analysis with a high degree of reliability and in a cost-effective manner.

Extensive test data have demonstrated that all tubular joints possess elastic flexibility, which varies depending on joint type, geometry and loadcase. It is generally recognized that the amount of brace rotation required to shed in-plane and out-of-plane moments at the joint is small and consistent with the imposed rotations from low amplitude waves, which, in the main, dominate fatigue life accumulation. The moments, in practice, would therefore be expected to be shed from the joints and be amplified at the brace member mid-span location.

Structural engineering mechanics suggest that, in essence, representing the joints with finite linear elastic flexibility (i.e. an accurate reflection of the way joints behave in practice), instead of no flexibility (i.e. infinitely stiff, typical present-day practice, inaccurate reflection of joint response), would result in a reduction of acting loads at the joints, with a commensurate increase in member loads to maintain equilibrium.

These conclusions are supported by in-service performance data [2] and a case study platform that highlights

the influence of joint flexibility in a fatigue life assessment is described in detail below.

Implementation of Local Joint Flexibility

There are several methodologies available to account for the effects of local joint flexibility [7-12] in offshore structures although it is regonised by Industry that the equations and implementation philosophy formulated by Buitrago et al [7] are the most robust. The methodology has been tailored to accommodate the element modeling capabilities of the SACS software [3] used currently by PCSB. The method involves inserting a short ‘flex-element’ at the end of the brace. The flex-element connects the brace to the surface of the chord.

Buitrago et al [7] gives explicit formulae to determine the local joint flexibilities for various joint types and geometries. These equations are directly employed to calculate the appropriate local joint flexibility. The result is then used to calculate the necessary area and inertial properties of the flex-element to represent the axial and bending (both in-plane and out-of-plane) stiffness of the joint.

The area, A, and the moments of inertia, I, of the flex-element are calculated as follows:

I = L E(LJFm) A = L E(LJFp)

Where: - L, is the length of the flex-element. (LJFm), is either the in-plane (IPB) or the out-of-plane bending (OPB) local flexibility (LJFp), is the axial loading local joint flexibility Validation of the LJF Methodology

In order to verify the implementation methodology, a simple model of a T-Joint was created using SACS software [3]. The T-Joint was given the same geometry as a test specimen selected from the Makino. Y et al [13-14]

database, which contains data relating to full-scale failure, tests on tubular joints. SACS analysis was carried out both with and without the flex-element. Five axial loading tests, two in-plane bending tests and two out-of-plane bending tests were used for the comparison.

The results of the validation study are presented in Table 4, Table 5 and Table 6 for axial, in-plane bending and out of the plane bending respectively. [Note: D=diameter of the chord, T=chord wall thickness, d=diameter of the brace, t=brace wall thickness and L= Length of Chord]. The results given in Table 4, Table 5 and Table 6 respectively show that, when the flex-element is included in the model, the predicted chord wall deformations of δflex (axial deflections) and θflex (moment rotations) show good agreement with the test results δtest and θtest respectively. Conversely, the rigid joint, δrigid and θrigid model values show no correlation to the test results and underpredict the deflections and rotations significantly.

SPE 101000 5

Table 4 - Comparison of Axial Loading

Table 5 - Comparison of In-Plane Bending (IPB)

Table 6 - Comparison of Out-of-Plane Bending (OPB)

Fig. 7 – Illustration Showing Importance of Local Joint Flexibility

Fatigue Analysis Results

A conventional, rigid-joint, spectral fatigue analysis has been carried out for a typical platform as shown in Fig. 7. The fatigue analysis was repeated with local joint flexibility explicitly modeled in the analysis. The resulting fatigue life predictions were then compared with the rigid-joint analysis results and with inspection results. The results of the spectral fatigue analysis with LJF implemented show that, in all cases, the fatigue-life predictions increased. This factor is the ratio of the life calculated using flexible joint modeling to that calculated using a rigid joint model. The average factors on life for each of the framing components were typically as follows:- Transverse frames:>10, Longitudinal frames:>5, Horizontal framing:>5.

Fig. 8 - Comparison of Rigid and Flexible Joint Fatigue Inspection Categorizations

Fig. 8 shows the number of joints that would be considered in underwater inspection campaign inspection. The categories identified below have been generated to group the inspected joints in order of predicted fatigue lives. The categories have been selected solely for purposes of assessing the impact of LJF on what might be considered a rational inspection prioritisation.

Category 1: Highest Priority, predicted fatigue lives of less than 10 years Category 2: High Priority, predicted fatigue lives between 10 and 30 years Category 3: Medium Priority, predicted fatigue lives of 30 to 60 years. Category 4: Inspection not justified on the basis of fatigue assessment

The example platform has been in place for thirty years; assuming a reasonable level of reliability in the fatigue life predictions, some of the Category 1 joints should have developed crack indications. A smaller proportion of the Category 2 joints may also have some visible indications.

T-Joint Geometry Chord Wall Deformation

Spe

cim

en n

o.

D(m

m)

T(m

m)

d(m

m)

t(mm

)

L(m

m)

Axi

al L

oad

(kN

)

δfle

x

δrig

id

δtes

t

TC-8 165.2 4.24 89.1 3.5 527 45.1 0.703 0.023 0.512

TC-12 318.5 4.5 139.8 4.4 1593 76.5 2.241 0.035 4.141

TC-13 457.2 4.9 89.1 3.0 2286 46.1 2.916 0.069 4.572

TC-76 165.4 4.55 61.0 2.76 495 58.8 1.127 0.056 1.472

TC-92 216.47 4.51 216.33 4.58 696 248 1.426 0.049 0.770

T-Joint Geometry Chord Wall Deformation

Spe

cim

en n

o.

D(m

m)

T(m

m)

d(m

m)

t(mm

)

L(m

m)

Axi

al L

oad

(kN

)

θfle

x

θrig

id

θtes

t

TM-39 355.4 15.1 317.4 8.7 1422.4 405 0.0093 0.0038 0.0081

TM-41 456.1 15.4 317.2 8.6 1828.8 341 0.0107 0.0041 0.0108

T-Joint Geometry Chord Wall Deformation

Spe

cim

en n

o.

D(m

m)

T(m

m)

d(m

m)

t(mm

)

L(m

m)

Axi

al L

oad

(kN

)

θfle

x

θrig

id

θtes

t

TM-1 216.42 4.5 216.4 4.56 696 18.0 0.0179 0.0006 0.0116

TM-2 216.45 4.5 165.55 4.53 698 6.80 0.0177 0.0007 0.0208

Structural engineering mechanics suggest that, in essence, representing the joints with finite linear elastic flexibility (i.e. infinitely stiff, typical present -day practice, inaccurate reflection of joint response) would result in a reduction of acting loads at the joints.

Extensive test data have demonstrated that all tubular joints possess elastic flexibility, which varies depending on joint type, geometry and load case

30

25

20

15

10

5

0 Cat. 1 Cat. 2 Cat. 3 Cat. 4

No.

of J

oint

s

Rigid-joint Analys Fixed-joint Analysis

Joint Inspection Categories

6 SPE 101000

Assuming that Category 1 and Category 2 joint are included in the periodic inspections, the implementation of LJF in the fatigue analysis reduces the requirement for underwater inspection by approximately 70% as shown in Fig 8.

Foundation Capacity Assessments

A number of new design methods for predicting the pile bearing capacity have recently been developed as follows:

• Fugro-05 (Kolk et al [15] , Fugro 2004 [16] ) • ICP-05 (Jardine et al [17] ) • NGI-05 (Karlsrud et al 2005 [18], Aas et al 2004 [19]) • UWA- 05 (Lehane et al [20])

The traditional method in offshore design practice for predicting pile axial capacity of piles into silica sands uses criteria specified in API RP 2A. The predicted unit friction and end bearing values are predominantly based on soil classification and estimated relative density. Various design methods have been developed during recent years, which suggest that considerably more accurate predictions can be made through direct correlation of pile bearing capacity and end bearing with results from in-situ Cone Penetration Tests (CPTs). All of the above mentioned methods adopt the Cone Penetration Test (CPT) end resistance qc as the primary input parameter as opposed to existing non CPT based API design method as outlined in the API recommendations. The main reason why CPT based design criteria has yet to replace those in API is probably due to insufficient pile load test data to support the new criteria. The CPT, qc value is now commonly used directly in design methods for onshore driven piles De Cock et al. [21] and there has been growing support for the inclusion of such a method in the API recommendations for offshore driven piles. Fortunately, results from pile load tests have now become available, several of these pile test data sets having been presented at the ISFOG [22] conference. An example, comparing the predicted pile compression capacity using the above CPT methods with current API method is shown in Fig. 9. It can be seen from Fig. 9 that the API method predicts the lowest capacity when compared with the CPT based methods.

Fig. 9 – Prediction of Compression Pile Capacity between CPT and API Methods

To illustrate this fact further some results from ISFOG 2005, [22] have been extracted and shown in Table 7. The results have been obtained from comparing the ratio of capacities calculated by each method to measured capacities from a database of pile tests. It can be seen from Table 7 that for example for piles in compression the API method predicts the lowest capacities with a mean predicted to measured ratio of 0.78 and 0.75 for close-ended and open-ended piles respectively. It can been seen from Table 7 that the mean and COV’s (coefficient of variance) obtained by the four CPT methods are in general a significant improvement on the existing API recommendations.

Method Mean= Predicted/Measured

Coefficient of Variation,(COV)

API-00 0.78 0.56 Fugro-05 1.24 0.39 ICP-05 0.99 0.33 NGI-05 1.16 0.40

Driven Closed-ended Compression (CEC)

UWA-05 0.98 0.33 API-00 1.12 0.84 Fugro-05 0.97 0.41 ICP-05 1.02 0.30 NGI-05 1.27 0.50

Diven Closed-ended Tension (CET)

UWA-05 1.00 0.29 API-00 0.75 0.68 Fugro-05 1.14 0.30 ICP-05 0.89 0.28 NGI-05 1.01 0.25

Driven Open-ended Compression (OEC)

UWA-05 0.98 0.19 API-00 0.72 0.76 Fugro-05 0.90 0.32 ICP-05 0.90 0.27 NGI-05 1.01 0.35

Driven Open-ended Tension (OET)

UWA-05 0.91 0.23 API-00 0.81 0.67 Fugro-05 1.11 0.38 ICP-05 0.95 0.30 NGI-05 1.11 0.37

Full Database

UWA-05 0.97 0.27

Table 7 - Assessment of CPT and API Methods against Pile Database [221

Ageing Effect

The pile bearing capacity calculated according to the API recommendations is valid for a “young” platform where the excess pore pressures around the pile (developed during pile driving) have just dissipated. In most cases this will be about 3-4 months after installation in clay and just a few hours in sand. Research and field tests in different parts of the world indicate that for many types of soil including clays, silt as well as sands the pile bearing capacity increases with set-up time. For fully consolidated piles NGI, Clausen and Aas [23] suggested that a reasonable model for the change in pile capacity with time, due to ageing, can be expressed as: Q(t) = Q(to) · [ 1+ (Δ10) · log10 (t/to) ] Q(t) = capacity after t days Q(to) = capacity at the reference time in days. to = 30 days for sand, = 100 days for clay Δ10 = capacity increase for a ten-fold time increase.

30

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50

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0 10 20 30 40 50 60

Qtotal, c (MN)

Dep

th (m

)

API

NGI

ICP

FUGRO

UWA

Clay

Thin Clay Layer

Qtotal, c (MN)

AAPI

NGI

FUGRO

ICP

UWA

SPE 101000 7

The increase in pile capacity over time for values of (Δ10) of 0.1 and 0.2 respectively is illustrated in Fig 10. For example, a platform installed for 25 years would give an estimated increase in capacity of 20-30% respectively for (Δ10) values of 0.1and 0.2 respectively.

Fig. 10 – Development of Bearing Capacity with Time

The value of (Δ10) may in principle be determined from load tests carried out on identical piles after different times. In practice, the value of (Δ10) needs to be estimated from load tests carried out on the same pile at different times after driving, and by the previous test loading which is not a straight forward matter to isolate the time effect. For piles in clays, the database referred to by Karlsrud et al [18] and Clausen et al [23] consists of 121 individual load tests from 47 different sites. From 7 of these sites, piles have been tested at different times after installation. According to Karlsrud et al 2005 [18] the following (Δ10) value for time correction of the measured skin friction values in clay is also suggested by the following: (Δ10) = 0.1 + 0.4 · (1 – PI/50) · OCR-0.8 0.1 < (Δ10) < 0.5 Where: - PI (Plasticity Index) and OCR (Over Consolidation Ratio) are average values along the pile shaft.

As indicated above the Plasticity Index (PI), is considered to be an important index reference parameter with regard to the evaluation of long-term static capacity. Studies such as Karlsrud et al [18] above and by Skov and Denver [24] also indicate that there are some effects of soil plasticity on ageing pile capacityand generally show that the increase of pile friction, with time is lower for high plasticity clays and higher for low plasticity clays. A review of some of the soil types at locations within SKO region indicate that they consist mainly of clays with typical high PI in the shallower depths between 40 – 60% and of low to medium PI in the deeper depths with PI = 12 – 26%. An example of such is shown in Fig. 11. Data from 5 of the 7 sites O’Neill et al [25], Hutchinson and Jensen [26], Karlsrun and Haugen [27], Eide et al [28], and Bond and Jardine[29], where piles have been tested at different times after installation, cover the range of plasticity interest (particularly

in the deeper soil layers which mainly contribute to the pile capacity). The ranges covered by the datasets being between 13%-30% respectively. Results from these datasets suggest and upper and lower bound (Δ10) of 0.2 and 0.1 respectively. With the consideration of the deeper layers of low to intermediate plasticity clays being of most relevance and importance to the contribution to pile skin friction it is conservative to assume a value of (Δ10) = 0.1. For piles in sandy soil a lower bound (Δ10) = 0.15 - 0.20 was found by Skov and Denver [24] for short-term ageing effects.

Fig. 11 – Plasticity Index Measurements

Design Shear Strength

For many of the platforms approaching 25 years and above soil boring investigations and assessments conducted at the time prior to installation were conducted in the late 70’s and early 80’s. The pile prediction capacties at these times would be lower due to the use of the earlier API recommendations (circa 1987) and lower values would be estimated for unit skin fricrtion particularly in the clay layers. Pile ultimate axial bearing capacities are now calculated based on the updated design profiles, using API-RP2A recomendations [30]. It is noted that the API recommended method, or α-method for pile capacity was substantially updated after 1986 to become less conservative based on more field test results.

Design shear strength profile is normally selected based on boring, laboratory and CPT data and regional experience. As recommended by API-RP2A [30], the design profile should be selected more based on triaxial unconsolidated undrained compression test (UU) results. This appears particularly true for the deeper stiff to very stiff clays where other strength measuring devices such as torvane and pocket penetrometer have exceeded their capacities and disturbances due to sampling often occurred. Whilst the design shear strength

0

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0 5 10 15 20 25 30 35 40

Setup Time,Years

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Clay Sand

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0 20 40 60 80 100

Plasticity Index, Ip (%)

Average

8 SPE 101000

profile generally follows the one for normally consolidated clay it is updated on the more weightage for UU results in the deeper clays. Comparison is made for these design profiles with UU results as shown in Fig. 12.

Fig. 12 – Undrained Shear Stregth Data – Soil Boring Investigation Results

Fig. 13 - Reanalysis of Ultimate Pile Capacity Curve

A typical pile capacity versus pile penetration curves is presented in Fig. 13. The reanalyzed increase in pile capacity between API Pre-1987 and 1993 is shown in Table 8 is due to the increase in undrained shear strength in the deeper clays.

Typical increase in pile capacity due to improved design undrained shear strength and ageing effects of up to 30% is shown in Fig. 13 and Table 8. The example shown here considers the soil strata to consist mainly of clay. However, offshore sites throughout the various regions in Malaysia consist of both clay and sand soil profiles. Therefore, the contributions of both clay and sand layers have to be considered when deriving the pile capacities. Therefore, further work is required and is currently subject of future assessments being currently conducted by PCSB.

PILE CAPACITY (MN) IMPROVEMENTS (%)

Orig

inal

(A

PI P

re-1

987)

Rea

naly

sed

(AP

I-199

3)

Rea

naly

sed

+ A

gein

g

AP

I-199

3 V

S A

PI P

re-1

987

Rea

naly

sed

+ A

gein

g V

S A

PI-1

993

Rea

naly

sed

+ A

gein

g V

S A

PI P

re-1

987

15.32 17.20 19.90 12 16 30

Table 8 - Comparison of Pile Capacity Improvements between API Pre-1987 and API-1993 with Ageing Consideration

Detailed Assessments

Although the above improvements can have a significant impact on improving the strength, fatigue and foundation capacities for improved/refined code assessments there may be situations that even with these improvements the structure still does not meet the requirements. In such cases more detail assessments are required to account for either limiting strength or fatigue.

Platform Ultimate Strength

One of the key detail assessments that is undertaken is ultimate strength analysis. The ultimate strength of an offshore structure is usually evaluated using non-linear finite element analysis of a structural model, often termed pushover or collapse analysis. Typically the analysis is undertaken by applying the gravity loading as an initial load step. The concurrent metocean design load for the chosen direction is then applied to the model, and the lateral loading is factored incrementally until the ultimate strength of the structure is reached, typically characterized by a plateau in the global load-deflection behavior of the structural model. Alternatively, the wave height or storm severity is increased rather than factoring the design load. The latter method is often applied if the air gap of the structure is small, such that wave-in-deck loading may be accounted for in the ultimate response of the structure.

The ultimate strength assessment considers load redistribution and allows members and joints, including piles, to undergo plastic deformation, carrying loads past yield or buckling; also loads are redistributed within the system until the structure collapses. Members and joints may exhibit a reduced strength in the form of damage caused by overload, having crossed over buckling or inelastic yielding. In this context, damage is acceptable to individual or groups of

Original

Reanalysed

Reanalysed with ageing

Original Outer Skin Friction Original Ultimate Pile Capacity Reanalysed Ultimate Pile Capacity Reanalysed Ultimate Pile Capacity with Ageing

0 5 10 15 20 25 30 35

Ultimate Bearing Capacity (MN)

0

8

16

24

32

40

48

56

64

72

Dep

th B

elow

Mud

line

(m)

0

10

20

30

40

50

60

70

80

0 40 80 120 160 200

Undrained Shear Strength (kPa)

Dep

th B

elow

Mud

line

(m)

Clay Sand

Updated Soil Investigation result UU Data

SPE 101000 9

members as long as the integrity of the structural system against collapse is not compromised.

An ultimate strength assessment of a platform determines the actual system capacity of the analyzed structure. A structure will have a different ultimate strength for each predominant wave direction; the most important ultimate strength for a structure is the lowest, which is likely to be associated with the weakest direction or the most severe metocean loading. Reserve Strength Ratio

The ultimate strength of an offshore structure is expressed in terms of the Reserve Strength Ratio (RSR), which is a measure of the structure's ability to withstand loads in excess of those determined from the platform's design. The RSR is quantified as the ratio of the structure's ultimate strength to a reference level load. For PCSB structures the reference level load is determined by the 100-year extreme environmental metocean loading. For each structure there is a separate RSR for each metocean direction, it should also be noted that the metocean condition/direction that results in the highest component utilizations or highest base shears may not always produce the lowest platform RSR.

Reserve Strength and Residual Strength

Several sources contribute to the reserve and residual strength, which are a result of explicit and implicit conservatisms made during the design of an offshore structure. These aspects of a structure's design have been published in several papers (Lalani, et al, [6]), (UK HSE, Research Report 087 [31]), (UK HSE, OTO 97 046 [32]) and some of the saliant features are suimmarised below.

Design Safety Factors

The design of offshore structures is based on traditional engineering practice, which applies a combination of loads to the structure to determine the internal forces in each brace member. For each member and joint in the structure an allowable strength is provided in the design, and the structure is considered to meet the selected standard if all the individual components satisfy the requirements. All structural recommended practice, whether they are based on permissible stress design (Working Stress Design, WSD) address the design of individual members and joints. Within this design procedure is the premise that failure of one member or joint to satisfy the requirements, constitutes non-compliance with the relevant RP.

Implicit Design Safety Factors

Implicit sources of reserve strength are a result of strength conservatisms that are outside the control of the designer. Members have reserve strength beyond first yield, which contributes to the global reserve. Assuming that most modern jacket structures have strong joints and that the system failure is dominated by member failure, the implicit safety factor will be dominated by the differences between the effective length factor (K-factor) used in design and the actual K-factor for compression members.

Material Strength

The actual material yield strength is typically higher than the minimum allowed for in the design of the structure. Actual yield strength values can be between 5-20% above the specified minimum (Baker, [33]). This additional yield strength provides an increase in structural capacity not accounted for in the design.

Foundation Capacity

Small-scale centrifuge geotechnical tests by a major operator in the early 1990's O’Connor et al [34] indicate that the ultimate lateral capacity of pile foundations is higher than expected. The tests used a small-scale pile in clay soils typical of the Gulf of Mexico. These tests indicated that the pile ultimate capacity was not equal to the "degraded" capacity, as used in design, but instead to the "un-degraded" capacity. The conclusion of this work was that for design level loading the degraded soil strength is correct. However, for ultimate capacity loading, where the pile will see large deformations, the un-degraded strength is more correct.

The conclusions from this study are also consistent with observations from in-service performance history where there have been few observations of platform foundation failures. For example, such as from Hurricane Andrew, where Puskar et al [35] indicates that platforms designed to RP2A standards, no matter which era, tend to have an "unknown bias" in capacity of about 20% above the capacity that is a "best estimate." In simple terms - even when engineers use their best approaches to estimate the platform strength, the Andrew study demonstrated that there is an additional 20% reserve strength within the platform system (deck/jacket/piles). The assessment also showed that a significant proportion of the bias appears to be in the foundation. This is confirmed by the lack of observed foundation failures in Andrew System Redundancy

Each structure has an inherent reserve and/or residual strength, which are directly related to the ability of the structure to provide alternate load paths after failure of a member. This redundancy in the structural system (or robustness) is primarily associated with the arrangement of the braces within the system. A reduction of component capacity does not necessarily imply that the system strength is compromised. This will depend on whether or not the component is participating in the failure sequence that produces the system collapse mechanism, or whether the member's integrity is required to realize that particular mechanism.

Redundancy analysis simulates the total loss of the connected member, by removing the member from the model and performing a non-linear collapse analysis. This analysis is known as member importance. The redundancy analysis is carried out to evaluate the consequences of system failure due to severe fatigue cracks in the joints. It is used to identify high consequence versus low consequence joints. High consequence joints are defined as joints where fracture implies a significant reduction in the platform capacity and they should be subjected to a more rigorous underwater inspection planning. Low consequence joints have less impact on the platform capacity. The outcome from the redundancy analysis

10 SPE 101000

is used as a screening for all fatigue sensitive/defect joints whereby comprehensive underwater inspection planning can be properly addressed for high consequence joints but not for the low consequence joints.

The redundancy analysis treats cracking of each joint as an independent damage event. Worst case scenario is projected in this analysis whereby the fatigue crack is assumed to have propagated to a level causing total loss of the member. The probability of loosing two members simultaneously, i.e. two independent damage events happen concurrently, is considered to be relatively small. The derived RSR will then be subjected to the following governing inequality:

EFFDFFFF

RRRSR ESDSSF

FS ....)

/,( +≥

where: RSRderived =Derived reserve strength ratio

RSRtarget =Target reserve strength ratio RS =Non-linear structural strength RF =Non-linear foundation strength D =Dead load, permanent load and live load E =Environmental load FD =Partial load factor on dead load, permanent load and live load FE =Partial load factor on environmental load FS =Partial material factor for structure FF =Partial material factor for foundation

The partial load and material factors and the target RSRtarget can be obtained through Structural Reliability Analysis (SRA). Similarly, the derived RSRderived can be transformed into annual probability of failure through Structural Reliability Analysis. Using the aforementioned inequality, a high consequence joint can be classified as a joint in which the fracture of its connecting member will result in a lower derived RSRderived as compared to the target RSRtarget, and vise versa for the low consequence joint. The results from the redundancy analysis are used as a measure to avoid costly inspection of low consequence joints, and focus inspection on areas where fatigue and/or defect of the joint implies a significant reduction in platform capacity. For high consequence joints, the annual probability of failure, obtained through Structural Reliability Analysis, can be used to determine the extent of inspection.

Typically RSRtarget values would depend on the level of risk associate with the platform. Risk is the combination of the consequence of Platform Failure (Life Safety- (Manned-non evacuated), (Manned-evacuated) and Unmanned), and other Consequences such as environmental and economic) and the Likelihood of Failure. Each platform has a Likelihood of Failure based on key structural characteristics that affect the platform's reserve and residual strength, such as the RP used for design, the structural redundancy and robustness (tolerance to damage) provided by the number of legs and bracing configuration. Changes in platform condition such as damage or degradation may also increase the Likelihood of Failure.

Determining the Platform Risk can be accomplished by using a risk matrix approach, as is common in the industry such as the 5X5 Matrix used by PCSB as shown in Fig. 14.

Fig. 14 – Risk Matrix

Different acceptance criteria would normally be associated for Manned and Un-manned platforms typically target annual probability of failures of 1.10-4 and 1.10-3 respectively would be considered.

Procedure for Determinig Optimal Inspection Plan

To ensure the structural integrity of the ageing platforms, a cost effective monitoring program for the fatigue prone/sensitive joints would typically involve the following steps:

Step 1. Identify joints, which are required for inspection through spectral fatigue analysis.

Step 2. Perform probabilistic fracture mechanics analysis on the identified joints.

Step 3. Develop a reliability based inspection schedule for predefined target reliability.

Step 4. Perform redundancy analysis on the ageing platform by applying non-linear collapse analysis

Step 5. Determine the extent of inspection through optimal inspection planning

To demonstrate the above a number of non-linear push -over analysis have been conducted for a platform which did not meet the API RP2A [1] code requirements. Initially a non-linear collapse analysis using the USFOS software package was conducted for the intact structure (i.e assuming no damage) to identify the worse loading direction. A number of redundancy analyses were then performed to evaluate the consequence of critical fatigue sensitive joints based on spectral fatigue analysis, underwater inspection reports and probabilistic fracture mechanics analysis. All primary braces connected to those joints were selected for further investigation. For each of the critical fatigue sensitive joints identified the primary brace connected to these joints are selected for further analysis. The resulting RSR gives the strength of the structure without the affected member, i.e. worse case scenario for fatigue crack in that one joint. The relative reduction in platform strength is then compared to the strength of the intact structure. Results of the analysis for a number of different member removals are shown in Table 9 and Fig.15 and Fig.16 respectively. The results show that the removal of a primary diagonal or horizontal member would

5

4

3

2

1

A B C D E

Very Low

Medium

Low

High

Very High

Acceptable

Not Acceptable

RISK LIMIT

Consequence of Failure

Like

lihoo

d of

Fai

lure 5

4

3

2

1

A B C D E

Very Low

Medium

Low

High

Very High

Acceptable

Not Acceptable

RISK LIMIT

Consequence of Failure

Like

lihoo

d of

Fai

lure

SPE 101000 11

not have any significant impact on overall integrity of structure. Member

Removed Brief Description RSR %

41 Diagonal above mudline, row 1 2.84 -0.070%

37 Diagonal above mudline, row 1 2.85 -0.035%

18 Diagonal above mudline, row B 2.83 -1.05%

5 Diagonal above mudline, row A 2.86 0.00%

23 Diagonal above 1st elevation, row B 2.79 -2.45%

49 Diagonal above 1st elevation, row 1 2.84 -0.70%

12 Diagonal above 1st elevation, row A 2.87 +0.35%

328 Horizontal 1st elevation, row B 2.85 -0.35%

346 Horizontal 1st elevation 2.85 -0.35%

Table 9 - Impact of Removing Critical Members on Reserve Strength Ratio (RSR).

Fig. 15 - Reserve Strength Ratios for Different Member Importance Analysis Performed

Fig. 16 - Global Displacement Curve Illustrating Member Importance Analysis

PCSB has carried out structural integrity assessment for a number of platforms to evaluate the impact of fatigue failure of the high consequence joints utilising the aforementioned approach. Before the redundancy analysis, the total number of comprehensive inspections required, is 328. After redundancy nalysis, the total number of comprehensive inspections has been reduced to 59, which correspond to a significant reduction of 82 %. The results also show that 10 of the 13 platforms had achieved a reduction of 50 % and above in the number of inspections required, as highlighted in Table 10. The application of the methodology shows that only 18% of joints out of the total number of fatigue sensitive joints requires underwater inspection planning. Resources can then be optimally used by focusing inspections only on these relevant joints, resulting in considerable savings in cost and time.

Platform Fatigue sensitive joints

High cons. Joints

No Of Inspections Before Redundancy Analysis

No. Of Inspection After Redundancy Analysis

% of joints for inspection After Redundancy Analysis

A 13 6 18 9 50 %

B 23 6 38 11 29 %

C 7 - 20 - 0 %

D 1 1 1 1 100 %

E 14 - 33 - 0 %

F 32 - 76 - 0 %

G 4 - 9 - 0 %

H 15 - 45 - 0 %

I 8 7 12 11 92 %

J 5 3 7 5 71 %

K 11 3 16 3 19 %

L 4 1 6 1 17 %

M 21 9 47 18 38 % Total 158 36 328 59 18 %

Aver. 12 3 25 5 18 %

Table 10 – Sumary of Optimal Inspction Planning For Ageing Platforms

Structural Integrity Management System (SIMS)

PCSB is currently embarking on development of the implementation of SIMS. The SIM is a process for ensuring the fitness-for-purpose of an offshore structure from installation through decommissioning. Specifically, SIM is a rational means for managing the effects of degradation, damage, changes in loading, accidental overloading, changes in use, and the experience gained during the evolution of the offshore design practice. In addition to also capture engineering improvements such as those highlighted so far in this paper. SIM provides a framework for the inspection planning, maintenance, and repair of a platform or group of platforms.

3.5

3

2.5

2

1.5

1

0.5 0.5 1 1.5 2

23

328

Original 18

Load

Leve

l

Load Displacement Curve

Displacement (m)

12 SPE 101000

The process of PCSB SIMs is to follow that contained in the the proposed API Recommended Practice for Structural Integrity Management [(RP 2SIM, [35]) for fixed offshore platforms. The process contained in the RP 2SIM is illustrated in Fig.17 and consists of four primary elements: Data, Evaluation, Strategy and Program. The process is continuous and sequential and provides a logical framework for SIM. The approach is based upon an engineering evaluation of information arising from: the original design of the structure, inspection findings throughout its life, damage, overloading, and changes in loading and/or use. The RP 2SIM process process is generally consistent with the ISO SIM process. As new SIM data is collected it is evaluated to determine whether it increases operating risk, i.e. either the consequence or likelihood of platform failure. The role of assessment engineering within the SIM process is illustrated in Fig. 18.

Fig. 17– The SIM Process

Fig. 18 – Assessments within the SIM Process

Data may come from in-service inspections, platform modifications or other sources such as new technology or industry learning. If the operating risk has increased significantly then some level of assessment engineering is required to determine whether the platform remains fit-for-

purpose or whether risk reduction or mitigation measures are required. Risk reduction measures include options to decrease the likelihood of failure such as strengthening, modification or repair. Risk mitigation options include operational changes to reduce consequences of failure e.g. demanning. Reduction and mitigation alternatives will have financial and operational implications. For that reason it is usually cost-effective to use appropriate assessment engineering techniques to determine the fitness-for-purpose of the facility.

A clear distinction between design and assessment engineering is recognized in the SIM process. The new RP will serve as a companion to API RP 2A, which will be restructured to focus solely on the engineering of new platforms, with the new document focused on the integrity management of existing platforms.

RP 2SIM will contain updated versions of the above and below water Structural Survey (Section 14) and Platform Assessment (Section 17) from the present RP 2A. The document will also contain guidance on data collection, risk based inspection (RBI), assessment methods, assessment criteria, damage assessment, upgrades and repairs, and platform decommissioning. Presently there is no explicit RP requirement to encourage the regular use of ultimate strength methods in the design of fixed offshore platforms for metocean conditions.

As previously highlighted in this paper RPs for the design of offshore platforms are based on the design of individual members and components and generally have no formal requirement to structural system strength beyond the component requirement. API RP 2A is a component-based RP; therefore the strength of the structure is defined by the strength of the weakest component. System strength is not addressed and benefit cannot be taken in design from load redistribution. The proposed new RP [35] will provide alternative acceptance criteria for platform fitness-for-purpose assessments. The criteria will be in the form of acceptable RSRs and will be applicable for the assessment of all platforms. To maintain consistency with the present RP, the acceptance criteria will be consequence-based and differentiate between older and newer platforms, such that platforms designed to API RP 2A 20th edition or later will have more stringent RSR criteria.

Also the present API RP 2A provides a prescriptive approach for platform inspections. The proposed API RP 2SIM will provide an alternative for a "Risk-Based Inspection," where inspection intervals and inspection work scope can be based on the combination of the platform's RSR (likelihood of failure) and platform's consequence of failure.

Conclusion This paper has presented the current methodology for undertaking reassessment of its current fleet of platforms. Although RP codes of practice are used as the initial basis of these assessments in many cases the requirements to satisfy the minimum requirements of these RP may not be met for trigger events as highlighted in this paper. Two significant areas where this is particularly true namely foundation and fatigue requirements have been identified in this paper. In such cases there is a need to exploit current conservatisms in

Dat

a

Eva

luat

io

Stra

tegy

Pro

gram

Managed system for archive and retrieval of SIM data and other pertinent record.

Overall inspection philosophy & strategy and criteria for in-service inspection.

Detailed work scopes for inspection activities and offshore execution to obtain quality data.

Evaluation of structural integrity and fitness for purpose; development of remedial action.

Dat

a

Eva

luat

ion

Stra

tegy

Pro

gram

Initi

ator

Tr

igge

r

Assessment

Yes

SPE 101000 13

the assessment process and apply engineering improvements that currently exist. These engineering improvements as demonstrated in this paper can lead to substantial improvements in foundation pile capacity and fatigue life estimates and result in more reliable assessments. As such the need to perform uneccessary costly and hazardous underwater inspections, strengthening or modifications may not be required enabling further development of the field development to be considered.

Not withstanding the application of such improvements there may still be cases where the structure still does not meet the refined code assessment. In such cases there is a need for more detail analysis including the application of non-linear ultimate strength push over analysis to determine both the system strength and residual strength as a result of critical member removal such as a high consequence fatigue joint. An example presented in this paper shows that the structure has significant reserve strength above the reference load of 100 year extreme environmental metocean condition and the elastic limit which is the basis of code requirements.

In addition it has been demonstrated that by removing members who may be deemed to be critical (i.e. those with low fatigue life) the removal of such members do not have a significant influence on reducing the reserve strength. It should be noted that only the influence of fatigue critical joints has been included in this paper. Other high consequence members identified such as those which may have extensive corrosion or damaged members due to drop objects and boat impact should also be considered in the member removal analysis. It is apparent that consideration should be given to the use of ultimate strength assessments as an important decision-making tool in the design of new structures and, more importantly, during the life-cycle SIM for existing offshore structures. Through more realistic evaluation and observation of a platform's structural behavior, one can gain a better understanding of the structure's integrity and susceptibility to damage. This increased knowledge can be used to determine the criticality of components within the structural system and to assess inspection and repair schemes.

Future Developments PCSB is currently undertaking a number of technology initiatives to develop standalone internal recommended practices to exploit the current engineering improvements in both fatigue and foundation strength that have been highlighted in this paper. A Fatigue RP (PSCB) Guideline, which will include amongst other things the implementation of LJF and improved S-N, curves into our current structural assessments and structural analysis software packages. Furthermore, a Foundation RP Guideline which will include a detail review of the current new design methods highlighted in this paper together with available pile database and current research on ageing effects, with the view of identifying the most appropriate method(s) for the various offshore Malaysia site-specific soil conditions.

PSCB is also currently embarking on the implementation of CSIMS to manage the ongoing structural Integrity of its platforms. The process adopted is to be inline with the recent development of RP 2SIM and ISO highlighted in this paper. In

addition to adopting this approach it has recently joined a JIP (Joint Industry Project)[36] involving a number of non-US Operators for developing the API RP 2SIM document (currently applicable to Gulf of Mexico) to extend its applicability to Non-US Waters.

The criteria (like that being developed for GOM) will be developed as Regional Annex’s in the form of acceptable RSRs for the given metocean conditions, applicable to the region and will be developed so as to be applicable for the assessment of all platforms. It will be written in such a manner to make it consistent with similar ISO guidance on SIM, and will provide considerably more in-depth guidance for maintaining existing platforms than is presently available in RP 2A.

Not withstanding the above there are other structural integrity challenges, which PCSB is currently facing for trigger events for which platforms were not originally designed for, such as the presence of shallow gas and seismic earthquake loading.

PCSB intends to present future papers to provide an update on the implementation of current technology, CSIMS and JIP initiatives discussed in this paper, together with fitness of purpose assessments due to shallow gas and seismic events. Acknowledgments

The authors would like to thank the management of PCSB for their kind permission to present this paper.

References: 1. API RP2A-WSD “Recommended Practise for Planning, Design

and Constructing Fixed Offshore Platforms”, 21st Edition, Dec. 2000.

2. O.T. Vardal, Aker Offshore Partner, T. Moan, Norwegian University of Science and Technology, N. C. Hellevig, Aker Offshore Partner. “Comparison between Observed and Predicted Characteristics of Fatigue Cracks in North Sea Jackets”, Paper OTC 10847 presented at the 1999 Offshore Technology Conference, Texas, 3-6 May 1999.

3. Engineering Dynamics Incorporated (EDI). “Structural Analysis Computer System – User Manual”, Volumes I to IV.

4. American Welding Society, Structural Welding Code, AWS D1.1, ANSI Document.

5. ISO/CD 19902, Draft E June 2004, International Standards Organization, Petroleum and Natural Gas Industries - Offshore Structures – Part 2: Fixed Steel Structures.

6. Lalani M. “New Large scale Frame Data on the Reserve and Residual Strength of Offshore Structures”, ERA Conference, London, 1993

7. Buitrago, J., Healy, B. E. and Chang, T.Y. “Local joint flexibility of tubular joints”, Offshore Mechanics and Arctic Engineering Conference, OMAE, Glasgow, 1993.

8. Ueda, Y., Rashed, S. M. H., and Nakacho, K., "An Improved Joint Model and Equations for Flexibility of Tubular Joints", Journal of Offshore Mechanics and Arctic Engineering, vol. 112, pp. 157-168, 1990.

9. Hu, Y., Chen, B., and Ma, J., "An Equivalent Element Representing Local Flexibility of Tubular Joints in Structural Analysis of Offshore Platforms", Computers and Structures, vol. 47, No. 6, pp. 957-969, 1993.

14 SPE 101000

10. Chen, B., Hu, Y., and Tan, M., "Local Joint Flexibility of Tubular Joints of Offshore Structures", Marine Structures, Vol. 3, pp. 177-197, 1990.

11. Chen, T. Y. and Zhang, H. Y., "Stress Analysis of Spatial Frames with Considerationof Local Flexibility of Multiplanar Tubular Joint", Engineering Structures, Vol. 18, No. 6, pp. 465-471, 1996.

12. Romeyn, A., Puthli, R. S., and Wardenier, J., "Finite Element Modelling of Multiplanar Joint Flexibility in Tubular Structures", Proceedings of the Second International Offshore and Polar Engineering Conference, Vol. IV, International Society of Offshore and Polar Engineers, pp. 420-429, 1992.

13. Makino, Y et al “Behaviour of Tubular T- and K- joints under Combined Loads”, OTC 5133, OTC, 1986, Houston.

14. Makino, Y et al “Database of Test and Numerical Analysis Results for UnstiffenedTubular Joints”, IIW Doc XV-E-96-220, Kumamoto University, Kumamoto, Japan.

15. Kolk, H.J., Baaijens, A.E. & Senders, M. 2005, “Design criteria for pipe piles in silica sands”, in International Symposium on Frontiers in Offshore Geotechnics, Perth, Western Australia.

16. Fugro 2004, “Axial pile capacity design method for offshore driven piles in sand”, P-1003, Issue 3, to API.

17. Jardine, F.M., Chow, F.C Overy, R.F. & Standing, J.R. 2005a, “ICP design methods for driven piles in sands and clays”, Thomas Telford, London.

18. K.Karlsrud, C.J.F Clausen and P.M.Aas, “Bearing Capacity of driven piles in Clay, the NGI approach”, Proceedings of the First International Symposium on Frontiers in Offshore Geotechnical, University of Western Australia, Perth, ,19-21 September 2005

19. Aas, P.M., Clausen, C.J.F. & Lacasse, S. 2004, “Bearing capacity of driven piles in sand based on pile load tests”, Presentation, 7 May 2004, Texas A&M, IOBT.

20. Lehane, B.M., Schneider, J.A. & Xu, X. 2005c, “The UWA-05 method for prediction of axial capacity of driven piles in sand”, Proceedings of the First International Symposium on Frontiers in Offshore Geotechnical, University of Western Australia, Perth, ,19-21 September 2005

21. De Cock, F., Legrand, C. & Huybrechts, N., “Overview of design methods of axially loaded pile in Europe – Report of ERTC3-Piles, ISSMGE Subcommitte’, in Proceeding 8th European Conference on Soil Mechanics and Geotechnical Engineering, Prague, pp. 663-715, 2003.

22. Proceedings of the First International Symposium on Frontiers in Offshore Geotechnical, University of Western Australia, Perth, ,19-21 September 2005

23. Clausen, C.J.F. and P.M. Aas, “Capacity of Driven Piles in Clays and Sands on the Basis of Pile Load Tests”, ISOPE Conference 2001.

24. Skov, R and H. Denver, “Time-dependence of Bearing Capacity of Piles”, Proc. 3rd International Conf. On the Application of Stress-wave Theory to Piles, Ottawa, 1988.

25. O’Neill M. W, R.A.Hawkins and J.M.E. Audibert, “Installation of Pile Group in Overconsolidated Clay” , ASCE, JGED, No. GT12, 1982.

26. Hutchinson, J.N. and E.V. Jenson, “Load Tests on Piles Driven into Estuarine Clays of Port of Khorramshahr, Iran and Observations of the Effect of Bitumen Coatings on Shaft Bearing Capacity”, NGI Publ. No. 78, Oslo, 1968.

27. Karsrud K. and T. Haugen, “Axial Static Capacity of Steel Model Piles in Over-consolidated Clays”, Proc. 11th Int. Conference SMFE, San Francisco, 1985.

28. Eide O., J.N. Hutchinson J. and A. Landva, “Short and Long Term Test Loading of a Friction Pile in Clay”, Proc. 5th Conference SMFE, Paris, 1961.

29. Bond A.J. and R.J. Jardine, “Shaft Capacity of Displacement Piles in a High OCR Clay. Geotechnique”, Vol. 45, No. 11995.

30. API RP2A-WSD “Recommended Practise for Planning, Design and Constructing Fixed Offshore Platforms” , 20 Edition, 1993.

31. UK HSE, “Comparison of Reserve Strength Ratios of old and New Platforms Offshore Technology Repor”, OTO 97 046, June 1997.

32. UK HSE, “System-based calibration of North West European annex environmental load factors for the ISO fixed steel offshore structures code 19902”, Research Report 087.

33. Baker, M.J. “Variability in the Strength of Structural Steel – A Study in Structural Safety part I Material Variability” CIRIA Technical Notes 44, 1973.

34. Puskar, F. J., Aggarwal, R. K., Cornell, C. A., Moses, F., and Petrauskas, C., '” Comparison of Analytically Predicted Platform Damage to Actual Platform Damage During Hurricane Andrew”, Proceedings 26th Offshore Technology Conference, OTC No. 7473, May 1994.

35. O’ Connor P.E., BP; Bucknell J.R., MSL; DeFrance S.J., BP; Westlake H.S., MSL; and Puskar F.J., Energo Eng. Inc,“ Structural Integrity Management (SIM) of Offshore Facilites”, Paper OTC 17545 presented at the 2005 Offshore Technology Conference, Texas, 2-5 May 2005.

36. O'Connor, P. E., Versowsky, P., Day, M., Westlake, H. S., and Bucknell, J., “Platform Assessment: Recent Section 17 Updates and Future API/Industry Developments', Proceedings”, Offshore Technology Conference, Paper No. 17699, May 2005.